1. Field of the Invention
This invention pertains generally to fracturing of oil and gas bearing and other geological formations, and, more specifically, to a method of extending fracture geometry farther into a target formation by increasing in-situ stress in adjacent formations or in adjacent portions of the same formation.
2. Brief Description of the Prior Art
When wells are drilled into geological rock formations for the purpose of producing oil, gas, or water from such formations or for other purposes, such as injection of fluids into the formation, mining, and the like, hydraulic fracturing is a primary method for increasing fluid production or injection rates. In general, one way to fracture a formation is to pump a fluid down a casing or tubing in a well and into the target formation at a sufficiently high pressure and injection rate to overcome in-situ stresses and force a fracture to open and propagate in the formation. Such hydraulically induced fractures, often called “hydraulic fractures” or just “fractures”, usually extend in a substantially vertical plane in radially opposite directions from the well-bore, although unique in-situ stress conditions in particular formations can cause different fracture orientation. When the fracture is opened and propagated in the formation, an additional and/or different medium is usually pumped into the fracture, to extend the benefits of the fracture over a long term after the fracturing fluid pump and pressure is stopped, such as a proppant material to keep the fracture open or an acid to dissolve minerals from the fracture walls to produce a conductive pathway along the fracture after it is closed. Consequently, in fractured oil and gas bearing formations, the oil and gas can flow more easily via the fracture to the well. Likewise in fractured fluid injection formations, fluid can flow more easily from the fluid injection well into the formation via the fracture. Fractures can also be formed in other ways, such as with explosives or gas, but hydraulic fracturing is by far the most common fracturing technique.
In moderate to low permeability formations, the farther the fracture extends from the well into the target formation, the better the level of stimulation and associated production response. However, in many hydraulic fracturing operations, the fracture geometry exhibits growth in undesirable directions, which, as some have hypothesized, tend to follow the direction perpendicular to the least in-situ tectonic compressive stress in the formation, i.e., usually in a vertical projection along a plane parallel to the maximum, naturally occurring (tectonic) compressive stress field. Several patents, including U.S. Pat. No. 4,005,750 issued to L. Shuck, U.S. Pat. No. 4,687,061 issued to D. Uhri, U.S. Pat. No. 5,111,881 issued to Soliman et al., and U.S. Pat. No. 5,482,116 issued to El-Rabaa et al., illustrate several techniques for modifying in-situ stress fields in localized areas around the well bore to change the initiation and propagation direction of hydraulically induced fractures to extend in other desired directions, even perpendicular to the typical fracture direction in the naturally occurring (tectonic) compressive stress field. Generally, these techniques involve first creating and propping open ordinary fractures that extend parallel to the maximum naturally occurring (tectonic) compressive stress field, which increases the in-situ stress proximate to that fracture, and then creating another fracture that initiates and propagates in a different direction away from such increased stress fields. The U.S. Pat. No. 4,869,322 issued to Vogt, Jr. et al. uses a similar technique to obtain a vertical fracture in unusual formations that favor propagation of horizontal fractures.
Besides influencing propagation direction of hydraulic fractures, however, an equally important goal is to get the fractures to extend as far as possible from the well bore into the formation. U.S. Pat. No. 4,515,214 issued to Fitch et al. and U.S. Pat. No. 4,509,598 issued to Earl et al. address this problem by injecting proppant of a carefully determined density into a fracture with low viscosity fluids (i.e., slurry mix) to screen out the slurry mix and pack or seal marginal edges or tips of fractures. The theory is that a lower density proppant packs upper edges and a higher density proppant packs lower edges or tips of the fracture, thus inhibits growth of the fracture in the directions of such packed edges or tips, e.g., upwardly or downwardly, and thereby forcing continued lateral propagation farther away from the well bore and into the target formation. However, these procedures have had only limited success in the oil and gas industry, perhaps because the lower and upper fracture tip growth is not really slowed to any significant extent by this technique in many fracture operations.
Efforts have also been made to use reduced injection rates or lower viscosity fluids to reduce net fracturing pressure below the pressures required to propagate fractures in adjacent formations with the hope that the fracture would stay in the target formation. However, many rock types have similar tensile strengths and fracture at similar pressure levels, regardless of injection rate and viscosity, thereby limiting any benefits from this technique.